U.S. patent application number 14/530767 was filed with the patent office on 2015-04-30 for intelligent electronic device with broad-range high accuracy.
The applicant listed for this patent is Electro Industries/Gauge Tech. Invention is credited to Tibor Banhegyesi.
Application Number | 20150120230 14/530767 |
Document ID | / |
Family ID | 39793345 |
Filed Date | 2015-04-30 |
United States Patent
Application |
20150120230 |
Kind Code |
A1 |
Banhegyesi; Tibor |
April 30, 2015 |
INTELLIGENT ELECTRONIC DEVICE WITH BROAD-RANGE HIGH ACCURACY
Abstract
A method and apparatus provides high-accuracy measurements of an
electrical parameter across a broad range of parameter input
values. In one embodiment, an intelligent electronic device (IED),
e.g., a digital electrical power and energy meter, with a plurality
of independently-adjustable gain factors measures a parameter, and
calculates and stores calibration factors associated with known
values of the measured parameter. The IED or meter applies the
stored calibration factors when measuring unknown values of the
measured parameter, to improve the accuracy of the measurement.
Inventors: |
Banhegyesi; Tibor; (Baldwin,
NY) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Electro Industries/Gauge Tech |
Westbury |
NY |
US |
|
|
Family ID: |
39793345 |
Appl. No.: |
14/530767 |
Filed: |
November 2, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13204789 |
Aug 8, 2011 |
8878517 |
|
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14530767 |
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|
12055448 |
Mar 26, 2008 |
7996171 |
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13204789 |
|
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60920198 |
Mar 27, 2007 |
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Current U.S.
Class: |
702/85 |
Current CPC
Class: |
G01R 22/065 20130101;
H05K 7/1424 20130101; G01R 21/00 20130101; G01D 18/008 20130101;
G01R 22/06 20130101; G01R 35/00 20130101 |
Class at
Publication: |
702/85 |
International
Class: |
G01R 35/00 20060101
G01R035/00; G01R 21/00 20060101 G01R021/00 |
Claims
1. An intelligent electronic device comprising: a sensing circuit
having one or more sensors for sensing at least one parameter of an
AC electrical service, each of the one or more sensors generating a
first signal representative of the sensed parameter; a plurality of
gain-adjustable channels, each channel having at least one gain
adjustment circuit for individually adjusting a gain factor and
each channel comprising at least one first signal generated by the
one or more sensors, the at least one first signal representative
of the sensed parameter; one or more computer-readable storage
devices; and a plurality of calibration factors stored in the one
or more computer-readable storage devices, the plurality of
calibration factors corresponding to a plurality of calibration
measurements, the plurality of calibration measurements comprising
measurements of a second signal representative of a known value of
the parameter at a plurality of signal amplitudes in each of a
plurality of calibration ranges.
Description
CROSS-REFERENCE TO RELATED PATENT APPLICATIONS
[0001] This application is a continuation application of U.S.
application Ser. No. 12/055,448, filed on Mar. 26, 2008, which
claims priority to expired U.S. Provisional Patent Application No.
60/920,198, filed on Mar. 27, 2007, the contents of which is herein
incorporated by reference.
FIELD
[0002] This patent relates generally to the field of intelligent
electronic devices for electrical utility services and, more
specifically, to digital electrical power and energy meters for the
electrical utility services.
BACKGROUND
[0003] Producers, suppliers, and consumers of electrical power rely
on energy meters to monitor power consumption and quality for
numerous purposes, including billing and revenue calculations,
power distribution management, and process management.
Traditionally, the primary means of measuring power consumption was
an electro-mechanical power meter. A number of other types of
meters and equipment measured other parameters of power generation,
distribution, usage, and quality. As technology has improved,
intelligent electronic devices (IEDs), such as digital power and
energy meters, Programmable Logic Controllers (PLCs),
electronically-controlled Remote Terminal Units (RTUs), protective
relays, fault recorders, and the like, have slowly replaced their
electro-mechanical and analog counterparts. The shift to IEDs from
analog and electro-mechanical devices provides a vast array of
advantages, including improvements in measurement accuracy (e.g.,
voltage, current, power consumption, power quality, etc.) and
system control (e.g., allowing a meter to trip a relay or circuit
breaker).
[0004] The voltages, currents, and frequencies employed in the
various electrical systems that utilize IEDs vary widely from
region to region (e.g., the United States and Europe), from
application to application (e.g., industrial or residential), and
across various parts of a power distribution system (e.g.,
generation, transmission, delivery, etc.). For example, power may
be generated at one voltage (e.g., 30,000 V), but transmitted at
another, much higher voltage (e.g., 110,000 V), to minimize
heat-related power losses related to large electrical current in
the transmission lines. Additionally, a series of power
sub-stations transforms the voltages employed for transmitting
power, to bring the voltage down to the level at which it is
distributed to customers (e.g., 220 V). Industrial power consumers
in one region may receive power at one voltage (e.g., 480 V), while
residential consumers in the same region receive power at a second
voltage (e.g., 120 V). Residential consumers in one region may
receive power at one voltage and frequency (e.g., 120 V at 60 Hz in
the United States) while similar consumers in another region may
receive power at a different voltage and frequency (e.g., 230 V at
50 Hz in Europe).
[0005] Power measurements typically occur at a few
industry-standard voltages and frequencies. Higher operating
voltages and currents are reduced to a few standard current ranges,
so that the higher operating voltages and currents can be measured
by meters designed to measure within those voltage and current
ranges (e.g., 120 V, 208 V, 220 V, 277 V, 347 V, and 690 V).
However, the disparity in the voltages, currents, and frequencies
employed, not withstanding the relatively few standard ranges in
which measurements are taken, generally necessitates that different
IEDs be purchased for different input ranges, in order to comply
with the various standards which the IEDs must meet. For example, a
digital power and energy meter designed to measure power
consumption and quality at an industrial facility may be inoperable
or inaccurate--failing to meet industry requirements for the
particular application--if employed at a power generation
facility.
[0006] Thus, to comply with the requirements for accuracy among the
multiple standards adhered to across industries and geographical
regions, manufacturers of IEDs commonly configure and sell multiple
"options" for each model of meter, where each of the options
includes a voltage and current level that the purchaser expects the
meter to measure. The meters are thereafter calibrated to meet the
required standards. For example, one standard requires that energy
calculations be accurate to within 0.2%. While many meters are
calibrated to achieve an error of no more than 0.2% for one range
of input signal levels (e.g., 120 V or 69 V), measuring a different
range of signal levels requires recalibration to achieve the
desired accuracy. This requirement is often necessary because
part-to-part variations in the meter design, and offsets and/or
phase shifts in sensor and/or input networks, have varying effects
at different signal levels.
SUMMARY OF THE DISCLOSURE
[0007] An intelligent electronic device (IED), e.g., a digital
electrical power and energy meter, described herein is operable and
highly accurate while conducting measurement activities at each of
a number of different industry-standard voltage, current, and
frequency ranges. Specifically, the meter includes a plurality of
individually-adjustable gain-controlled channels, which selectively
regulate the amplitudes of the signals communicated to various
modules of the meter. The regulated signals, which are proportional
to the sensed supply voltages and supply currents of the electrical
service to which the meter is connected, may be adjusted to match
pre-determined ranges for input signals of the various modules of
the meter, so as to optimally utilize the dynamic range of the
included analog-to-digital converters. In addition, the processing
module of the meter may be designed to perform a series of voltage
and/or current calibration measurements, using known voltage and
current sources to determine a plurality of calibration factors for
use while measuring and/or monitoring the electrical service. The
meter utilizes these calibration factors to achieve optimal
accuracy when measuring within each of the ranges of voltage and
current in which the meter may operate. The calibration
measurements may further include performing each series of
calibration measurements at multiple frequencies, to achieve
optimal accuracy regardless of the frequency range of the monitored
signal.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIG. 1 depicts an exemplary electrical power distribution
grid for transmitting electrical power from a power plant to a
plurality of consumers and employing a plurality of digital
electrical power and energy meters.
[0009] FIG. 2 is a block diagram illustrating an exemplary digital
electrical power and energy meter.
[0010] FIG. 3 is a block diagram illustrating a metering module of
the exemplary meter of FIG. 2.
[0011] FIG. 4 is a block diagram illustrating a processing module
of the exemplary meter of FIG. 2.
[0012] FIG. 5 depicts the various contents of the memory module of
FIG. 4.
[0013] FIGS. 6A & 6B illustrate alternative methods for
calibrating a digital electrical power and energy meter.
[0014] FIGS. 7A & 7B illustrate sample sets of calibration
measurements and calibration factors corresponding to the methods
of FIGS. 6A & 6B, respectively.
[0015] FIG. 8 illustrates a method for applying a set of
calibration factors to a plurality of measurements.
[0016] FIGS. 9A and 9B depict two alternate methods for using
interpolation to achieve accurate measurements.
[0017] To facilitate understanding, identical reference numerals
have been used, where possible, to designate identical elements
that are common to the figures, except that suffixes may be added,
when appropriate, to differentiate such elements.
[0018] The appended drawings illustrate exemplary embodiments of
the present disclosure and, as such, should not be considered as
limiting the scope of the disclosure that may admit to other
equally effective embodiments. It is contemplated that features or
steps of one embodiment may beneficially be incorporated in other
embodiments without further recitation.
DETAILED DESCRIPTION
[0019] FIG. 1 depicts an electrical power distribution grid 10
including a number of electrical service environments which may
employ digital electrical power and energy meters, such as those
disclosed herein. A power plant 12 includes a plurality of
generators 14 powered by steam, coal, natural gas, nuclear reactor,
etc. Each of a plurality of digital electrical power and energy
meters 16 monitors various parameters (e.g., voltage, current,
frequency, power quality, etc.) of the output of the generators
14.
[0020] As illustrated in FIG. 1, the generators 14 transmit the
generated energy from the power plant 12 to a distribution
substation 18. At the distribution substation 18, one or more
step-up transformers 20 transform the energy generated by the
generators 14 from a relatively lower voltage (e.g., 10,000 V)
generated by the generators 14 to a relatively higher voltage
(e.g., 500,000 V) for transmission over long distances using
high-voltage transmission lines 24. A plurality of digital
electrical power and energy meters 22 may monitor the energy at
either or both of the inputs and the outputs of the step-up
transformers 20 to, for example, verify that proper voltages,
frequencies, and phase relationships are maintained, and generally
to monitor the overall health of the distribution grid 10.
[0021] A bulk power substation 26 receives the energy transmitted
over the high-voltage transmission lines 24 from the distribution
substation 18. One or more step-down transformers 28 in the bulk
power substation 26 transform the energy received over the
high-voltage transmission lines 24 from the transmission voltage to
a relatively lower voltage (e.g., 100,000 V). The bulk power
substation 26 also includes on or more buses (not shown) to allow
the energy to be directed in different directions for transmission
to multiple locations. Of course, the bulk power substation 26 may
employ a plurality of digital electrical power and energy meters 30
to monitor the energy at the substation 26, just as the meters 16,
22 monitor energy at the power plant 12 and the distribution
substation 18.
[0022] The bulk power substation 26 transmits the energy output
from the step-down transformers 28 to one or more distribution
substations 32. Each of the distribution substations 32 includes
one or more step-down transformers 34 for further transforming the
energy to a relatively lower voltage (e.g., 7,200 V) for
distribution to consumers, and may also include a plurality of
digital electrical power and energy meters 36 for further
monitoring of power parameters. The distribution substations 32
transmit the energy via local power lines 38 to various
distribution transformers 40. The distribution transformers 40
step-down the voltage once more to the distribution voltage (e.g.,
240 V or 480 V). From the distribution transformers 40, the energy
is transmitted to residential consumer facilities 42 (e.g., homes)
and industrial consumers facilities 44 (e.g., factories).
[0023] Industrial consumer facilities 44, in particular, may employ
a plurality of digital electrical power and energy meters 46, 48,
50, 52 throughout the industrial environment. For example, the
meter 46 may monitor the energy coming from the utility, as a means
of verifying that the utility is providing power of sufficient
quality (i.e., relatively free of sags and swells, having low
harmonic distortion, etc.) and not overcharging the industrial
consumer for more power than the utility actually delivers. Of
course, the utility may also monitor the energy and quality
delivered, using the meter 46. The meter 48 may be used, for
example, to monitor energy consumption by, and the quality of power
delivered to, one or more loads 54 within the industrial consumer
facility 44. Similarly, the meters 50 and 52 may monitor other
parts of the industrial consumer facility, such as back-up
generation capacity 56 (e.g., generators) and other loads 58
connected to the back-up generation capacity 56. In this manner,
the electrical power and energy meters 16, 22, 30, 36, 46, 48, 50,
and 52 may monitor energy creation, distribution, and consumption
throughout the distribution grid.
[0024] FIG. 2 depicts a block diagram illustrating an exemplary
digital electrical power and energy meter 100 which may be used to
implement any of the electrical power and energy meters 16, 22, 30,
36, 46, 48, 50, and 52 of FIG. 1. The meter 100 generally comprises
a metering module 110 for measuring or calculating one or more
parameters associated with the electrical load or service (e.g.,
voltage, current, energy, etc.) and a processing module 120 for
facilitating operation of the meter 100 and processing data
obtained from the metering module 110. The meter 100 may also
include a user interface unit 130 for displaying results of
measurements and calculations and allowing configuration of the
meter 100; one or more input/output (I/O) modules 135, for
facilitating communication of data to an external device (not
shown); a communications module 140 for coupling to one or more
remote terminals (not shown); and a power supply 150 for providing
power to the various components and modules of the meter 100. Said
(I/O) modules include but are not limited to transducer outputs
consisting of DC signals output by a digital to analog converter
which are proportional to the desired measured parameters in
exemplary ranges such as -1 to 0 to +1 mA outputs, 0 to 1 mA
outputs, 4-20 mA outputs or others wherein the user generally can
program the low scale and high scale parameter for the output.
Other input/output modules include Ethernet, Profibus, Lon Works,
telephone modem, wireless transceiver, cellular modem or phone,
relay outputs, pulse outputs, analog inputs and status inputs, etc.
Any one or more of these types of input/output modules are
considered facilitating communication of data to an external
network.
[0025] During normal operation, the metering module 110 may be
coupled to an electrical service to be measured and/or monitored,
such as the three-phase electrical service 101 of FIG. 2. A current
interface 107 and a voltage interface 109 couple the meter 100 to
supply lines 103 A, B, C, and N of the electrical service 101.
Alternatively, when calibrating the meter 100, the current
interface 107 and the voltage interface 109 may couple the metering
module 110 to a calibration reference 102. Manufacturers typically
perform meter calibration subsequent to assembly of the meter 100
and prior to shipping the meter 100 to the intended customer.
Calibration may also be performed at periodic intervals thereafter
over the lifetime of the meter 100. Each of the interfaces 107 and
109 may include a plurality of connections (indicated in FIG. 2 by
the bold connecting arrows), e.g., connections to each of phases A,
B, C, and N, in the depicted embodiment. U.S. patent application
Ser. No. 11/003,064, now U.S. Pat. No. 7,271,996, details some
methods of coupling digital electrical power and energy meters to
various electrical services. The connections of the interfaces 107,
109 may be, for example, screw-type connections, blade-jaw
connections, etc. Those of ordinary skill in the art will be
familiar with other methods for coupling meters to electrical
services, thus these methods need not be described further
herein.
[0026] The metering module 110 may include a sensing module 115 for
sensing the currents and voltages on the interfaces 107 and 109,
respectively, and generating for each sensed current or voltage, a
signal representative thereof. The sensing module 115 includes
voltage sensing circuitry 117 connected to the voltage interface
109, and current sensing circuitry 119 connected to the current
interface 107. In the depicted embodiment, the metering module 110
also includes a metering processor 118, for calculating one or more
parameters of the electrical service 101. In particular, the
metering processor 118 of the current embodiment may calculate
energy usage.
[0027] An interface 123, which communicatively couples the metering
module 110 to the processing module 120, may include one or more
buses connecting, for example, the metering processor 118 and the
sensing module 115 to the processing module 120. In one embodiment,
the interface 123 includes two analog signal paths from the sensing
module 115 to a processor 160, and digital data paths (e.g.,
address and data buses, a serial peripheral interface, etc.)
between the metering processor 118 and the processor 160. The
analog signal paths include additional analog channels for use by
the processor 160, as described in detail below. Interfaces 133 and
143 communicatively couple the processing module 120 to the user
interface module 130 and the communications and/or I/O modules 135
and 140, respectively. The interfaces 123, 133, 143 may be any type
of physical interfaces, and may be any appropriate logical
interfaces. For example, where each module resides on a separate
printed circuit board (PCB), each physical interface may include a
cable, a header/receptacle connector, a card-edge connector, or a
stackable connector. Each logical interface may include a serial
interface or serial peripheral interface (SPI), one or more
parallel data/address buses, etc. Said interfaces could be using an
electrical or optical means. Further, multiple modules may reside
on a single PCB, allowing the modules to be connected via
connections embedded in the PCB. Additionally, the modules need not
be physically distinct from one another, nor need the modules be
physically segregated.
[0028] In the embodiment depicted in FIG. 2, the processing module
120, which may be disposed on one PCB or on multiple PCBs, includes
the processor 160 (e.g., a micro-processor, a digital signal
processor (DSP), etc.) and a memory module 180 having one or more
computer-readable storage devices (e.g., memories). For example,
the memory module 180 may include an electrically erasable
programmable read-only memory (EEPROM) 182, a flash memory 184,
and/or a random access memory (RAM) 186. An interface 178, which
connects the processor 160 to the memory module 180, may be any
known interface compatible with the particular memory devices 182,
184, 186 and with the particular processor 160. The processing
module 120 may also include additional elements, such as a
real-time clock 196, a backup power source (e.g., a battery) 194,
and various other support circuitry 192. It is envisioned as part
of the present disclosure that the processing module 120 may
incorporate all elements such as processor 160 and memories 180 or
any other peripheral via on-board chip connections in which the
functions are included as part of a single semi-conductor device.
It is also envisioned that these modules can be located in separate
devices and in a combination of on-board and separate devices.
[0029] Referring now to FIG. 3, the voltage sensing circuitry 117
in the sensing module 115 may include three voltage dividers or
potential (or voltage) transformers (i.e., one for each of
electrical phases A, B, and C) 117A, 117B, 117C for proportionally
decreasing the voltage sensed by the metering module 110. The
current sensing circuitry 119 may include three conductors (i.e.,
one for each of electrical phases A, B, and C), each passing
through a toroidal coil 119A, 119B, 119C, a current transformer or
some other type of current sensing device such as current shunts,
rogowski coil, etc. The voltage sensing circuitry 117 and the
current sensing circuitry 119 generate signals representative of
the three voltages phases and the three current phases,
respectively.
[0030] The plurality of signals representative of the voltage and
current are communicated from the sensing module 115 to the
metering processor 118 via, for example, interfaces 121V and 121I.
The interfaces 121 may be any suitable interfaces, including, if
the sensing module 115 and the metering processor 118 are on a
single PCB, traces embedded in the PCB. In one embodiment, the
signals representative of the voltage and current are received by
the metering processor 118. The metering processor 118 includes
circuitry 112A, 112B, 112C, 114A, 114B, 114C for converting the
analog signals representative of the sensed currents and voltages
to digital signals (e.g., using analog-to-digital converters
(ADCs)), and circuitry 111A, 111B, 111C 113A, 113B, 113C for
applying a gain factor to the signals to effectively utilize the
full resolution of the ADCs. Of course, the ADCs 112A, 112B, 112C,
114A, 114B, 114C and/or the gain circuitry 111A, 111B, 111C 113A,
113B, 113C, may be discrete components and need not be included
within the metering processor 118. While the metering processor 118
illustrated in FIG. 3 includes three current ADCs 112A, 112B, 112C
and three voltage ADCs 114A, 114B, 114C (e.g., one ADC for each of
the sensed signals), fewer ADCs may be used if employed in
combination with a plurality of sample-and-hold registers and
multiplexers. In such an application, one ADC may convert the
voltage values and one ADC may convert the current values. Of
course, the ADCs must operate fast enough to perform all three (or
six) conversions before the sample time has elapsed. For example,
if two ADCs are employed (one each for voltage and current), and if
each phase is to be sampled 10 times per second (or every 100 ms),
each ADC must be capable of performing at least 30
analog-to-digital conversions each second (one every 100 ms for
each of the three phases).
[0031] Each gain circuit 111A, 111B, 111C, 113A, 113B, 113C may
include one or more gain-controlled amplifiers. Each
gain-controlled amplifier may selectively amplify a single output
signal of the sensing circuit (i.e., an input signal of the gain
circuit), according to a corresponding gain factor. The processing
module 120 may program the gain factor for each of the gain
circuits 111A, 111B, 111C and 113A, 113B, 113C, for example, by
setting a register (not shown) in the metering processor 118
through the interface 123. The gain factor for each of the
amplifiers in the gain circuits 111A, 111B, 111C, 113A, 113B, 113C
may be selected from a plurality of gain factors prior to measuring
the output of the sensing circuit 117, 119, such as by selection
via the user-interface 130 when a user knows the appropriate gain
factor for the electrical service 101 to which the meter 100 is
connected. Alternatively, the gain factor for each of the
amplifiers in the gain circuits 111A, 111B, 111C, 113A, 113B, 113C
may be selected in response to measuring the output of the sensing
circuitry 117, 119, allowing the meter 100 to adjust the gain
factors automatically and without user intervention and thereby
allowing the meter 100 to operate on any electrical service to
which it is connected. It should be recognized that the gain
factors selected for each of the gain-controlled amplifiers need
not be the same. Moreover, the plurality of gain factors available
for the gain-controlled amplifiers of the current gain circuit
111A, 111B, 111C need not be the same as those available in the
voltage gain circuit 113A, 113B, 113C.
[0032] A measurement parameter calculation routine 116 running on
the metering processor 118 uses the digital outputs of the ADCs
112A, 112B, 112C, 114A, 114B, 114C to determine the power or energy
on each phase (i.e., by multiplying the current by the voltage).
The metering processor 118 communicates the results of the energy
calculations across the interface 123 to the processing module 120.
Of course, the gain circuitry 111A, 111B, 111C 113A, 113B, 113C,
the ADCs 112A, 112B, 112C, 114A, 114B, 114C, and the energy
calculation routine need not be in a single chip such as in the
metering processor 118. For example, the current gain circuitry
111A, 111B, 111C and the voltage gain circuitry 113A, 113B, 113C
may each be a multi-channel variable gain amplifier, while the
current ADCs 112A, 112B, 112C and the voltage ADCs 114A, 114B, 114C
may each be a multi-channel ADC package. In such an implementation,
the power or energy calculation may be implemented on a specialized
metering chip or a stand-alone DSP.
[0033] Referring now to FIG. 4, the memory module 180 may store
data related to the operation of the meter 100 in a plurality of
areas 180A of the memory module 180. These data may include
operating parameters data 183 such as the settings of the device
(e.g., alarm triggers, communication configurations, data formats,
etc.); measured parameter data 181 such as harmonic information and
Fourier transforms; waveform data 189; power or energy calculation
data 188; various log data 187 of power quality events (e.g., sags,
swells, transients, etc.); a plurality of routines 185 necessary to
operate the meter 100 (e.g., gain control routines, waveform
capture routines, calibration routines, etc.); and calibration data
and/or tables 190. As used herein, the term "calibration data"
refers to calibration factors, and is used interchangeably as such.
As described below, the calibration factors may be offset data
("offset calibration factors") or linear slope data ("linear
calibration factors") or other types of calibration factors. The
data stored within the memory module 180 may be stored in the
memory module 180 in any manner known by those of ordinary skill in
the art. Moreover, these data need not be stored in a single device
(such as the EEPROM 182, the flash memory 184 or the RAM 186). For
example, the routines 185 and calibration data 190 may be stored in
the EEPROM 182, the log data 187 stored in the flash memory 184,
and the remainder of data stored in the RAM 186.
[0034] One or more buses 178 communicatively connect the memory
module 180 to the processor 160, depending on the processor and
memory devices employed. As shown in FIG. 4, the processor 160 may
also serve to communicatively couple the memory module 180 to the
other modules, such as to the metering module 110 (e.g., by the
buses 178 and 123). This connection may be necessary, for example,
to facilitate storage of energy measurements, to implement gain
control in the metering module 110, or to facilitate storage or
retrieval of calibration data, as will be discussed in detail
below.
[0035] The processor 160 runs or executes the routines 185 stored
in the memory module 180, and generally performs calculations and
otherwise manipulates data, in addition to administering operation
of the meter 100. The routines 185 may include, by way of example
and not limitation, an FFT routine 162, a gain control routine 164,
a waveform capture routine 168, a calibration routine 170, I/O
& communication routines 172, and administration routines
174.
[0036] In addition to the routines 185 described above for
administering operation of the meter 100 and processing data
obtained using the metering module 110, the processing module 120
may additionally execute one or more routines for implementing
virtual relay logic functionality. Virtual relay logic
functionality allows a user to configure the meter 100 to monitor
one or more parameters, and to detect when a numerical value of the
parameter meets or exceeds a pre-determined threshold. The
pre-determined threshold may be programmed by the user directly or
via a remote terminal (i.e., sending threshold settings to the
processing module 120 via the communication module 140), and may
include, for example, a minimum value or a maximum value for the
parameter. The parameter monitored in the virtual relay may be any
parameter measured by the meter 100, including actual or root mean
square (RMS) values of a line voltage, a line current, a phase
voltage, a phase current, or a total harmonic distortion, or may be
energy, revenue, real power, reactive power, total power, or a
power factor. When an "event" is detected, the processing module
120 may be configured to record the settings, timing, and values
associated with the event, or to transmit the information
pertaining to the event to a remote terminal, for display or
storage on the remote terminal. Moreover, information pertaining to
events may also be reported or signaled to a device external to the
meter 100 by changing a state of a relay contact or a solid state
contact, changing a state of a digital output on one of the I/O
cards, or changing a numerical value of an analog signal. In
addition to logic checking, virtual relay logic also allows users
to add additional parameters as defined in the programming section
to include parameters like and/or/nand/nor or any other desired
logical descriptor. Moreover, the logic could further be used to
obtain custom calculations such as conversion from Watts to
horsepower or to determine BTUs or the convert energy usage to
dollar cost, etc. Moreover, the logic may incorporate complex
instructions like to run specific executable code upon event or to
allow users to custom program and configure the meter (or IED)
using code or programming to add new functionality not envisioned
by the developer.
[0037] Additionally, the processor 160, may include circuitry 163
and 165 for implementing gain control on the additional voltage and
current signal channels coming from the sensing module 115 as part
of the interface 123 and converting the analog signals
representative of the sensed currents and voltages to digital
signals (e.g, using one or more ADCs). The processor 160 may use
the additional channels, each of which includes a voltage signal
and a current signal for each phase of the electrical service 101,
and the corresponding circuitry 163 and 165 for metering tasks that
require different gain factors than the gain factors used in the
energy metering functions executed on the metering module 110 to
fully utilize the dynamic range of the corresponding ADC. In
particular, the processor 160 may use one of the additional signal
channels to provide waveform capture functionality. In contrast to
calculating energy consumption (or generation), waveform capture
typically requires a much larger dynamic range to capture
transients such as voltage spikes (which may exceed the nominal
voltage of the system by orders of magnitude). The processor 160
may use another additional voltage signal channel and current
signal channel for calculating harmonic effects in the electrical
service, as capturing this information may require yet a different
dynamic range, and thus a different gain setting.
[0038] While a single processor 160 is illustrated in the
embodiment depicted in FIGS. 2 and 4, the processor 160 may be one
or more processors (e.g., two micro-processors, a micro-processor
and a DSP, etc.). Likewise, while FIG. 4 depicts the gain and ADC
circuitry 163 and 165 as disposed within the processor 160, these
components may be implemented separately from the processor 160 in
any known manner, such as those described above with reference to
the circuitry in the metering processor 118.
[0039] The following paragraphs describe the calibration features
of the meter 100. As described above, the processor 160 runs the
plurality of routines 185, which include one or more calibration
routines 170. With reference now to FIG. 5, the calibration
routines 170 may include, for example, a routine 200 for
determining and storing one or more calibration factors, which
calibration factors are indicative of the error between the actual
value of a measured parameter and the measured value of the
parameter. The routine 200 may calculate and store the one or more
calibration factors for each desired calibration range in which the
meter is to operate. The calibration routines 170 may also include
a routine 300 for using the stored calibration factors determined
by the routine 200 such that the measurement data reported or
recorded by the meter 100 represents the actual value of the
measured parameter. The calibration routines 170, examples of which
are described in more detail below, may also optionally include a
routine 400 for interpolating stored calibration factors to
determine additional calibration factors as described below. The
meter 100 may implement each of the calibration routines 170 using
multiple different methods, and each method may use one of several
types of calibration factors. Some of these methods will be
described below.
[0040] FIG. 6A depicts a flow chart describing a method 201,
corresponding to the routine 200, for determining one or more
calibration factors corresponding to a measured parameter in the
IED. In a first step 202, the meter 100 is connected, via the
interface 107 or 109 to a reference current and/or voltage source,
respectively, such as to the calibration reference 102, depicted in
FIG. 2. The calibration reference 102 provides a known current
and/or voltage signal, at a known (and usually selectable)
amplitude, to allow a comparison between the actual value of the
parameter being calibrated and the value of the parameter as
measured by the meter 100. In a step 204, the calibration reference
102 is set to provide a known signal amplitude in the calibration
range. For example, to calibrate the voltage measurements of the
meter 100 in the 277 V calibration range (which range has a
full-scale value of 500 V, thereby giving it a range of 0 V to 500
V, inclusive), the calibration reference 102 may first be set to
20.000 V. In a step 206, the value of the signal as measured by the
meter 100 is determined. In a step 208, the measured value is
compared to the actual value (i.e., the reference value). Using the
measured and actual values of the parameter (e.g., the voltage),
step 210 determines a calibration factor. Of course, the
calibration factor may be, for instance, an offset calibration
factor (i.e., a value that should be added or subtracted from the
measured value of the parameter to determine the actual value of
the parameter), a linear calibration factor (i.e., a value that
should be multiplied with the measured value of the parameter to
determine the actual value of the parameter), or some combination
of offset and linear calibration factors. Alternatively, the
calibration factor may be determined according to calculations of
average values or some other statistical method. Moreover, an
offset calibration factor may be a fixed offset or a variable
offset, which variable offset varies according to some
predetermined formula or criteria. At a step 212, the determined
calibration factor is stored in the memory module 180 (preferably
in a non-volatile memory such as the EEPROM 182 in FIG. 2) and, in
particular, the calibration factor may be stored as associated with
the measured value of the parameter.
[0041] FIG. 6B depicts a flow chart describing an alternative
method 221 for calibrating a measured parameter in the IED. In a
first step 222 the meter 100 is connected, via the interface 107 or
109 to a reference current source and/or a reference voltage
source, respectively, such as to the calibration reference 102,
depicted in FIG. 2. In a step 224, the calibration reference 102 is
adjusted until the signal amplitude provided by the calibration
reference 102 causes the meter 100 to measure a desired value in
the calibration range. For example, to calibrate the voltage
measurements of the meter 100 in the 277 V calibration range, the
calibration reference 102 may be adjusted until the value measured
by the meter 100 is 20.000 V. This may correspond to an actual
value (i.e., the value provided by the calibration reference 102)
of 19.802 V. At a step 226, the measured value is compared to the
actual value (i.e., the reference value). A step 228 then uses the
measured and actual values of the parameter (e.g., the voltage) to
determine a calibration factor. As described above, the calibration
factor may be an offset calibration factor, a linear calibration
factor, or any other type of calibration factor. At a step 230, the
determined calibration factor is stored in the memory module
180.
[0042] In either of the methods 201 and 221, the calibration factor
may be determined using known methods. For example, a linear
calibration factor (wherein multiplication of a measured value of a
parameter by the calibration factor converts the measured value of
the parameter to the actual value of the parameter), may be
determined by dividing the reference value (i.e., the actual value
of the parameter) by the value of the parameter as measured. This
computation may be expressed as:
F = X R X M ##EQU00001##
where F is the calibration factor, X.sub.R is the reference value
of the parameter, and X.sub.M is the value of the parameter as
measured by the meter 100. Likewise, an offset calibration factor
(wherein adding the calibration factor to a measured value of a
parameter converts the measured value of the parameter to the
actual value of the parameter), may be determined by finding the
difference between the reference value and the value of the
parameter as measured. This calculation may be expressed as:
F=X.sub.R-X.sub.M
[0043] Moreover, the steps 202 to 212 (or the steps 222 to 230) may
be repeated for each of the values in a particular calibration
range. Assuming, for example, that the calibration range is 277 V,
calibration measurements may be made (and calibration factors
determined) in, for example, 20 V increments (e.g., at 20 V, 40 V,
60 V, etc.). In this manner, a plurality of calibration factors may
be determined for the 277 V range of measurements. It should be
noted that the number of measurements in a given calibration range
may be as few as one. For example, in one alternative method for
calibrating a range of signals, calibration measurements may be
made at the range value (e.g., 277 V) and the full-scale value for
that range (e.g., 500 V), instead of at smaller increments within
the range. Alternatively, the meter 100 may determine one or more
calibration factors using averaging or other statistical
techniques. Moreover, the method 201 (or the method 221) may be
repeated, for each of the calibration ranges, at multiple
frequencies (e.g., 50 Hz and 60 Hz), to allow the meter 100 to
operate with improved accuracy regardless of the nominal operating
frequency of the electrical system 101. The meter 100 may store the
determined calibration factor or factors as an individual value
(e.g., where there is a single offset calibration factor or linear
calibration factor for each calibration range) or in a look-up
table or other data structure (e.g., where multiple offset or
linear calibration factors exist for each calibration range).
[0044] FIGS. 7A and 7B depict an example set of calibration
measurements and a set of example linear calibration factors
determined from the measurements that might result from the methods
201 and 221, respectively. As will be seen, the tables 240 and 260
have five columns. A column 242 depicts example values of signals
generated by the calibration reference 102. A column 244 depicts
example values of the signals generated by the calibration
reference 102, as measured by the meter 100. A column 246 depicts
the calibration factor calculated using the values in the columns
242 and 244. Lastly, columns 248 and 250 depict the error for the
particular example reference value before and after application of
the calibration factor, respectively. For example, the first row in
the column 242 of the table 240 shows a reference value of 20.00 V,
while the column 244 of the table 240 indicates that the value
measured by the meter 100 was 18.76 V. Thus, there is a measurement
error of 6.200% (indicated in the column 248 of the table 240). By
comparison, after application of the corresponding calibration
factor as depicted in the column 246 of the table 240, the error is
less than 0.2% (as depicted in the column 250 of the table
240).
[0045] The method 201 shown in FIG. 6A (or the method 221 shown in
FIG. 6B) is repeated for each of the desired calibration ranges
(e.g., 69 V, 120 V, 277 V, etc.). Thus, subsequent to calibration,
the memory module 180 of the meter 100 will contain calibration
data 190 for each of the desired calibration ranges, allowing the
meter 100 to operate with the desired accuracy (e.g., less than
0.2% error) in any of its intended operating ranges. Of course, the
calibrated parameters need not be restricted to voltage and
current. Additional parameters and/or measurements may also be
calibrated in each of any number of desired calibration ranges.
These parameters and/or measurements may include, by way of example
and not limitation, RMS current, RMS voltage, phase, apparent
power, reactive power, active power, frequency, etc.
[0046] FIG. 8 depicts a method 301, that may be implemented by the
routine 300, for using the stored calibration factors determined by
the routine 200 and stored in the memory module 180 to determine a
calibrated measurement (i.e., an actual value) of the measured
parameter. In a step 305, the meter 100 is connected, via the
interface 107 or 109 to an electrical service 101 which operates at
a nominal voltage with a nominal frequency. Further, the load (not
shown) on the electrical service 101 draws current at some nominal
capacity.
[0047] At a step 310, the processing module 120 assesses the
appropriate gain for each of the measured current and voltage
signals by first assessing the nominal values of the voltage and
current in the electrical system 101 (i.e., ignoring the effects of
transients, harmonics, etc.). The processing module 120 then
determines the industry standard nominal value for the voltage
(e.g., 69 V, 120 V, 230 V, 277 V, 347 V, 416 V, 721 V, etc.) and
the industry standard nominal range for the current (e.g., 0-1 A,
0-5 A, or 0-10 A). Next, the processing module 120 selects the
appropriate voltage gain and the appropriate current gain to
optimally utilize the full resolution of the ADCs 112A, 112B, 112C,
114A, 114B, 114C.
[0048] Those of ordinary skill in the art will appreciate that gain
adjustments for the supply voltages and currents may be performed
in a real time (i.e., dynamically) by a gain control routine 164
or, alternatively, the gain factors for the amplifiers 111A, 111B,
111C 113A, 113B, 113C may be pre-configured via the user interface
130 based on known characteristics of the electrical service 101 or
electrical load, which power consumption is monitored using the
meter 100. Additionally, the gain control routine 164 may operate
within the processor 160 of the metering module 120, as described
above and as depicted in FIG. 4, or may operate within the metering
processor 118. Further, the nominal values of the voltage and the
current in the electrical system 101 may be determined from the
output of the sensing module 115 (i.e., the voltage sensing
circuitry 117 and current sensing circuitry 119) or, alternatively,
from the output of the metering processor 118. Thus, in operation,
the step 310 allows the meter 100 to perform measurements of the
voltages and currents, regardless of their nominal values, with the
same high accuracy in the respective operating ranges of the meter
100.
[0049] At a step 315, the meter 100 measures the parameter to which
calibration data is to be applied. For example, if calibration data
exists for RMS voltage measurements (e.g., as the stored
calibration data 190 within memory module 180), the meter 100
measures the RMS voltage of the electrical service 101.
[0050] The processing module 120 determines one or more appropriate
calibration factors in a step 320. The appropriate calibration
factors may be selected based on one or more criteria including,
for example, the amplitude of measured parameter, the gain factors
applied to the current and/or voltage inputs, and the calibration
range in which the meter 100 is operating (e.g., if the meter is
attached to a 277 V system, the calibration factors for the 277 V
calibration range may be selected).
[0051] At a step 325, the meter 100 uses the one or more
calibration factors determined in the step 320 to calculate a
calibrated measurement (i.e., an actual value) of the measured
value of the parameter. Calculating the measured value of the
parameter to find the actual value of the parameter may require
multiplying the measured value by the linear calibration factor.
This action may be expressed mathematically as:
X.sub.A=X.sub.M*F
where X.sub.A is the actual value of the parameter, X.sub.M is the
measured value of the parameter, and F is the chosen calibration
factor. Alternatively, calculating the measured value of the
parameter to find the actual value of the parameter may require
adding the offset calibration factor (where offset calibration
factors are employed instead of linear calibration factors) to the
measured value of the parameter. This operation may be expressed
mathematically as:
X.sub.A=X.sub.M+F
The re-calculated data (i.e., X.sub.A) for the parameter is then
selectively stored in the memory module 180, displayed on the user
interface 130, and/or forwarded to a pre-determined addressee
(e.g., another module, a personal computer, etc.) via the I/O
module 135 or the communications module 140.
[0052] FIGS. 9A and 9B depict methods 401 and 451 for determining
one or more additional calibration factors using interpolation of
the previously determined and stored calibration factors. The
calibration method 201, described above, results in the calibration
factors stored in the memory module 180. While application of these
calibration factors in accordance with, for example, routine 300,
produces accurate measurements at the calibration values for which
measurements were taken, any measured value that falls between two
adjacent values for which calibration factors exist may not be as
accurate. For example, if calibration measurements were made (and
corresponding calibration factors determined and stored) at 20 V
and 40 V, a measured value between 20 V and 40 V would have no
corresponding calibration factors. While in some circumstances one
may be able to provide the required accuracy (e.g., less than 0.2%
error) by applying calibration factors for one or the other of the
two adjacent calibration measurements, increased accuracy may be
provided by using interpolation to find a more accurate calibration
factor.
[0053] The method 401 of FIG. 9A determines one or more additional
calibration data points using interpolation of the stored
calibration data. In a first step 405, the processing module 120
determines the calibration range in which the meter 100 is
operating. Calibration factors (F.sub.1 and F.sub.2) for the two
measured values (X.sub.M1 and X.sub.M2) of the parameter at which
adjacent calibration measurements were taken are determined in a
step 410. For example, where the measured value (X.sub.M3) of the
parameter is 30 V, the two measured values (X.sub.M1 and X.sub.M2)
adjacent points at which calibration measurements were taken may be
20 V and 40 V, and the corresponding linear calibration factors
(F.sub.1 and F.sub.2) may be 1.100 and 1.300, respectively.
[0054] At a step 415, the processing module 120 determines the
slope b of a line drawn between the linear calibration factors. The
slope b of such a line between the linear calibration factors may
be determined by the equation:
b = ( F 2 - F 1 ) ( X M 2 - X M 1 ) ##EQU00002##
In the example above, F.sub.1 and F.sub.2 are 1.100 and 1.300,
respectively, and X.sub.M1 and X.sub.M2 are 20 V and 40 V,
respectively. Therefore, b=0.10.
[0055] Having found the slope b, the processing module 120 applies
the slope to find the new calibration factor F.sub.3 in a step 420.
The calibration factor F.sub.3 may be determined by the
equation:
F.sub.3=(X.sub.M3-X.sub.M2)b+F.sub.2
Applying this equation in the example above to find a calibration
factor to apply to a measured value of 30 V (i.e., X.sub.M3=30 V),
it is determined that the calibration factor F.sub.3 is 1.200. This
new calibration factor may be applied to the measured value to find
the actual value (X.sub.A3) in the same manner as described with
reference to the method 301 (i.e., X.sub.A3=F.sub.3*X.sub.M3).
Optionally, a step 425 may store the newly determined calibration
factor for future use with the other calibration data 190 in the
memory module 180. Alternatively, the step 425 may store other or
additional data, such as the slope b of the line between the
calibration factors.
[0056] Interpolation may also be applied to the values of the
measured signals used to calibrate the meter 100, as shown in the
method 451 of FIG. 9B. At a first step 455, the processing module
120 determines the calibration range in which the meter 100 is
operating. A step 460 then determines the actual values
(X.sub.A1/and X.sub.A2) for the two measured values (X.sub.M1 and
X.sub.M2) of the parameter at which adjacent calibration
measurements were taken. For example, where the measured value of
the parameter (X.sub.M3) is 30 V, the two measured values (X.sub.M1
and X.sub.M2) at which adjacent calibration measurements were taken
may be 20 V and 40 V, and the corresponding actual values
(X.sub.A1/and X.sub.A2) may be 19.802 V and 38.835 V, respectively.
The processing module 120 may find the corresponding actual values
(X.sub.A1/and X.sub.A2) by calculating these actual values using
the calibration factors (F.sub.1 and F.sub.2) stored in the memory
module 180 as associated with the measured values (X.sub.M1 and
X.sub.M2). This calculation may be expressed as:
X A 1 = ( X M 1 ) ( F 1 ) X A 2 = ( X M 2 ) ( F 2 )
##EQU00003##
Alternatively, the actual values corresponding to the measured
values could be stored in addition to, or instead of, the
calibration factors, and the actual values may be retrieved
directly from the memory module 180 instead of being calculated. Of
course, both of methods 401 and 451 may also be used to determine,
by interpolation, additional offset calibration factors.
[0057] At a step 465, the processing module 120 determines the
slope b of the actual values. The slope b of the actual values may
be determined by the equation:
b = ( X A 2 - X A 1 ) ( X M 2 - X M 1 ) ##EQU00004##
In the example above, X.sub.A1 and X.sub.A2 are 19.802 V and 38.835
V, respectively, and X.sub.M1 and X.sub.M2 are 20 V and 40 V,
respectively. Therefore, in this example, b=0.001.
[0058] Having found the slope b, the processing module 120 uses the
slope b to find the new actual value X.sub.A3 in a step 470. The
actual value X.sub.A3 may be determined by the equation:
X.sub.A3=(X.sub.M3-X.sub.M2)b+X.sub.A2
Applying this equation in the example above to find the actual
value X.sub.A3 of a measured value of 30 V (i.e., X.sub.M3=30 V),
it is determined that the actual value X.sub.A3 is 29.319 V. Of
course, if desired, a step 475 may store this value in the memory
module 180 for future use.
[0059] The above procedures may also be used to determine, by
interpolation, calibration factors (or calibrated measurement
values) at frequencies other than the frequencies at which the
meter 100 may be calibrated (e.g., 50 Hz and 60 Hz). The
extrapolation process starts with determining the two (but not
limited to) calibration factors closest to the range of the
measured parameter. The next step is to apply the extrapolation
algorithm to determine the approximated calibration factor at the
given point where the parameter is measured at. The extrapolation
algorithm calculates the magnitude difference of the two factors
(factor 1, factor 2), and then calculates the ratio of the variable
range between the measurement point and factor 1, and the range
between factor 1 and factor 2. By applying this ratio with the
predetermined mathematical function (extrapolation type) to the
factors' magnitude difference and adding it to factor 1 magnitude,
results the new factor for the measured parameter. Other variables
can have their own calibration factors and can be used on
measurements at any given point using an interpolation algorithm.
It is envisioned by this application that the algorithm type,
(linear, cube, polynomial, etc.) is selectable to the variable type
that best fits the transfer curve. This is based on the
characterization of the measurements needed over the variable
range. This technique is not limited to amplitude calibrations and
for frequency but could also apply to temperature, drift, time,
phase angle or any other type of movement of the measured
parameter.
[0060] The calibration of the meter 100 over multiple input ranges
is advantageous, particularly when combined with multiple gain
channels as is disclosed herein. As described above, each
independently-adjustable gain channel allows the meter to use the
associated analog-to-digital converter in the most appropriate
resolution for the channel's dedicated task, while the plurality of
ranges over which the meter 100 is calibrated allows improved
accuracy across multiple input ranges. Thus, the combination of
features allows the meter 100 to accurately measure some electrical
parameters (e.g., current, voltage, etc.) over a wide range of
input values, while still providing sufficiently detailed capture
and/or analysis of other electrical parameters (e.g., waveform,
harmonics, etc.).
[0061] Although the foregoing text sets forth a detailed
description of numerous embodiments, it should be understood that
the legal scope of the present disclosure is defined by the words
of the claims set forth at the end of this patent. The detailed
description is to be construed as exemplary only and does not
describe every possible embodiment, as describing every possible
embodiment would be impractical, if not impossible. As a result,
one could implement numerous alternate embodiments, using either
current technology or technology developed after the filing date of
this patent, which would still fall within the scope of the
claims.
[0062] It should also be understood that, unless a term is
expressly defined in this patent using the sentence "As used
herein, the term `______` is hereby defined to mean . . . " or a
similar sentence, there is no intent to limit the meaning of that
term, either expressly or by implication, beyond its plain or
ordinary meaning, and such term should not be interpreted to be
limited in scope based on any statement made in any section of this
patent (other than the language of the claims). To the extent that
any term recited in the claims at the end of this patent is
referred to in this patent in a manner consistent with a single
meaning, that is done for sake of clarity only, so as to not
confuse the reader, and it is not intended that such claim term be
limited, by implication or otherwise, to that single meaning.
Finally, unless a claim element is defined by reciting the word
"means" and a function without the recital of any structure, it is
not intended that the scope of any claim element be interpreted
based on the application of 35 U.S.C. .sctn.112, sixth
paragraph.
[0063] Still further, while the figures and description herein are
specifically directed to digital electrical power and energy
meters, including revenue-quality certified meters, the concepts
disclosed in the present application may also be applied in the
context of other types of Intelligent Electronic Devices (IEDs)
including, for example, Programmable Logic Controllers (PLCs),
Remote Terminal Units (RTUs), protective relays, fault recorders,
and other devices or systems used to quantify, manage, and control
quality, distribution, and consumption of electrical power. Thus,
as used herein, the term "digital electrical power and energy
meter" refers broadly to any IED adapted to record, measure,
communicate, or act in response to one or more parameters of an
electrical service. These parameters may include, for example,
supply currents and supply voltages, their waveforms, harmonics,
transients, and other disturbances, and other corresponding
parameters, such as power, power quality, energy, revenue, and the
like. A variety of electrical service environments may employ IEDs
and, in particular, digital electrical power and energy meters. By
way of example and not limitation, these environments include power
generation facilities (e.g., hydroelectric plants, nuclear power
plants, etc.), power distribution networks and facilities,
industrial process environments (e.g., factories, refineries,
etc.), and backup generation facilities (e.g., backup generators
for a hospital, a factory, etc.).
[0064] Thus, although the disclosure herein has been described with
reference to particular illustrative embodiments, it is to be
understood that these embodiments are merely illustrative of the
principles and applications of the present disclosure. Therefore,
numerous modifications may be made to the illustrative embodiments
and other arrangements may be devised without departing from the
spirit and scope of the present disclosure.
* * * * *